1. Field of the Invention
The present invention relates generally to oilfield operations. More particularly, the present invention pertains to apparatus and methods for monitoring downhole conditions in hydrocarbon wellbores, including fluid characteristics and formation parameters, using fiber optic gauges and other instrumentation. Moreover, the present invention pertains to apparatus and methods for controlling downhole equipment or instrumentation from the surface of the wellbore.
2. Description of the Related Art
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. When the well is drilled to a first designated depth, a first string of casing is run into the wellbore. The first string of casing is hung from the surface, and then cement is circulated into the annulus behind the casing. Typically, the well is drilled to a second designated depth after the first string of casing is set in the wellbore. A second string of casing, or liner, is run into the wellbore to the second designated depth. This process may be repeated with additional liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing having an ever-decreasing diameter.
After a well has been drilled, it is desirable to provide a flow path for hydrocarbons from the surrounding formation into the newly formed wellbore. To accomplish this, perforations are shot through a wall of the liner string at a depth which equates to the anticipated depth of hydrocarbons. Alternatively, a liner having pre-formed slots may be run into the hole as the lowest joint or joints of casing. Alternatively still, a lower portion of the wellbore may remain uncased so that the formation and fluids residing therein remain exposed to the wellbore. Hydrocarbon production is accomplished when hydrocarbons flow from the surrounding formation, into the wellbore, and up to the surface.
In modern well completions, downhole tools or instruments are often employed. These downhole tools or instruments include, but are not limited to, sliding sleeves, submersible electrical pumps, downhole chokes, and various sensing devices. These devices are controlled from the surface via hydraulic control lines, electrical control lines, mechanical control lines, fiber optics, and/or a combination thereof. The cables or lines extend from the surface of the wellbore to connect surface equipment to the downhole tools or instruments.
Additionally, during the life of a producing hydrocarbon well, it is sometimes desirable to monitor conditions in situ. Recently, technology has enabled well operators to monitor conditions within a hydrocarbon wellbore by installing permanent monitoring equipment downhole. The monitoring equipment permits the operator to monitor downhole fluid flow, as well as pressure, temperature, and other downhole parameters. Downhole measurements of pressure, temperature, and fluid flow play an important role in managing oil and gas reservoirs.
Historically, permanent monitoring systems have used electronic components to provide real-time feedback as to downhole conditions, including pressure, temperature, flow rate, and water fraction. These monitoring systems employ temperature gauges, pressure gauges, acoustic sensors, and other instruments, or “sondes,” disposed within the wellbore. Such instruments are either battery operated, or are powered by electrical cables or lines deployed from the surface.
Recently, fiber optic sensors have been developed. Fiber optic sensors communicate readings from the wellbore to optical signal processing equipment located at the surface. The fiber optic sensors may be variably located within the wellbore. For example, optical sensors may be positioned to be in fluid communication with the housing of a submersible electrical pump. Such an arrangement is taught in U.S. Pat. No. 5,892,860, issued to Maron, et al., in 1999. The '860 patent is incorporated herein in its entirety, by reference. Sensors may also be disposed along the production tubing within the wellbore. In either instance, a cable is run from the surface to the sensing apparatus downhole. The cable transmits optical signals to a signal-processing unit at the surface of the wellbore.
In order to connect downhole sensors with signal processing equipment at the surface, fiber optic and electrical cables and lines must be connected through downhole production equipment such as packers and/or annular safety valves. This downhole production equipment represents a barrier through which downhole cables must travel to reach the downhole equipment to which the cable is to be connected. To minimize time spent feeding cable through the barriers at the production site, segments of cable are often placed through these barriers prior to reaching the production site. Cable connectors are then placed on the segments of cable so that the segments may be connected at the production site to the cable run into the wellbore from the surface equipment.
When downhole cables are used to connect downhole equipment to surface equipment, the cables are typically wrapped around the working string to take up the slack in the length of the cable. The cables and cable connectors are thus left unprotected from the harsh and turbulent environment present in the wellbore. Consequently, fluid flow around the production string below the tubing-casing packer threatens the integrity of the cables and cable connectors. Of even greater concern is trauma inflicted on cables during initial run-in. In this respect, it is understood that many wellbores are drilled at deviated and highly deviated angles, meaning that cables external to the production string are subject to abrasion against the liner strings and any open hole wellbore portion. Wear and tear on the cables and cable connectors may force replacement of the cables or cable connectors, resulting in increased operating expense and lost production time.
Additional problems also arise from the placement of cable along production tubing. When fixed lengths of cable are used, the operator often attempts to space out the required length of cable along the existing length of the production string or other tubing disposed within the wellbore. This task is often impossible due to the different lengths of cable that are used in wellbore operations. In order to take up slack in the cable, the operator must wind the cable around the production string. In some instances, the operator must wrap the cable multiple times around the tubing to take up the slack, even crossing the cable over itself or with other cables. Crossing the cable is disadvantageous because the cable juts outward radially from the tubing, thus becoming more easily damaged due to increased exposure to the wellbore fluids over time and due to contact with the wellbore during run-in.
Thus, there is a need for an apparatus which protects ordinarily exposed cables and cable connectors from damage due to downhole conditions. There is a further need for an apparatus which allows cable to be wrapped in an orderly fashion around the tubing within the wellbore, thus controlling the location of the cable within the wellbore and preventing damage due to the crossing of cables and attempts to take up slack in a cable line.